Hydraulic fracturing is well known for use in stimulating the production of hydrocarbons, such as oil or natural gas, from subterranean formations.
A fracturing fluid is injected through a wellbore and propelled against the formation rock by high pressure sufficient to cause the rock to crack and fracture. The fracturing fluid also carries proppant to the fracture site which remains in the fracture thereby propping the fracture open when the well is in production. The proppant material is commonly sand, but can be sintered bauxite, glass beads, or synthetic materials such as polystyrene beads and the like. In order to facilitate the transportation of the proppant into the formation, the fracturing fluid must have sufficient viscosity or the proppant particles may settle out in the wellbore and cause piling problems, known in the industry.
The development of gelling hydrocarbons to obtain suitable viscosity to carry the proppant in fracturing fluids was reviewed by Weldon M. Harms in Oil-Field Chemistry (ACS Symposium #396-1988) published by the American Chemical Society in 1989 in a chapter entitled “Application of Chemistry in Oil and Gas Well Fracturing”, at pages 59-60.
Conventionally, the fracturing industry has preferred a gellant system suitable for fracturing which forms a gel in less than 30 seconds and preferably less than 20 seconds so as to be able to be prepared immediately before fracturing. Typically, gellant is added to the hydrocarbon and the hydrocarbon is then rapidly passed through a proppant tank, “on the fly”, where the hydrocarbon must have sufficient viscosity to pick up and hold the proppant in the fracturing fluid for injection into the wellbore. Preferably the gellant is cost effective and relatively simple to produce, is a liquid for ease of handling, is stable over a broad range of temperatures and can be broken when desired to permit flowback to the wellbore. Many known aluminum-based gellant systems are solids which require significant time to solubilize in the hydrocarbon and often, the application of heat, before gelling occurs. Thus, these systems cannot be used to prepare fracturing fluids “on the fly”.
Typically, hydraulic fracturing can be performed using either oil-based fluids or water-based fluids. It is known, for oil-based fluids, to develop viscosity using organometallic compounds to cross-link fatty acids or phosphate esters. For water-soluble fracturing fluids, the development of viscosity can be achieved by using organometallic compounds to cross-link naturally occurring polysaccharides, such as modified cellulose products (hydroxyethyl cellulose (HEC) and carboxymethyl hydroxyethyl cellulose (CMHEC)), guar and derivatized guar or derivatized xanthan gum. Typically, cross-linkers for oil-based gels are aluminum or iron and for water-based gels would be borates, zirconates or titanates.
Upon completion of the fracturing job, the gelled fluid must be returned to a natural fluid state so as not to cause formation damage by leaving gelled material in the pore spaces of the formation rock which would thereafter impede the flow of liquid or gaseous hydrocarbons out of the wellbore. Accordingly, breaker additives are used. One of the most common problems experienced with gelled fluids is the inability of the gels to break cleanly and to flow back out of the formation once the proppant is set and the pressure is released at surface. The breaking or drop in viscosity is typically achieved by the addition of the breaker additives into the fracturing fluid package. The breaker additives frequently work by oxidation, counter ions or pH or a combination thereof and may be time delayed so as to allow the fracturing job time to complete before the gel is broken.
The use of oil-based fracturing fluids has grown in popularity due to the presence of sensitive clays in some hydrocarbon bearing formations which react adversely with water in water based fracturing fluids. Oil-based fluid fracturing is more expensive than water-based fluid fracturing, but is less likely to cause formation damage due to swelling of the sensitive clays that may be in the formation.
Prior to 1970, the oil and gas industry employed the use of various types of surfactant and fatty acid-organometallic salts to viscosify hydrocarbon fluids for hydraulically fracturing hydrocarbon-bearing formations. The industry eventually changed to phosphate ester-based chemistry in an attempt to address shortcomings with the fatty acid technology of the time which were primarily related to economics of having to supply heat which is costly, especially in the colder climates including Canada and Russia and the slower than required speed at which gels formed. Thus, the current state in the industry is one in which the majority of oil-based fracturing fluids are viscosified with phosphorus-based chemistry; more specifically, fluids are viscosified using phosphate esters that have been cross-linked with aluminum or iron-based organometallic compounds.
Phosphate esters are commonly used, in combination with a metal cross-linker or activator such as an iron or aluminum salt, to gel hydrocarbons for use as a fracturing fluid. Following fracturing, broken gels are flowed back from the well and ultimately combine with crude streams for sale to refineries. The flowback fluids typically contain residual oil-soluble phosphate esters. Some phosphorus esters exhibit volatility when heated above 250° C., thus when crude containing phosphate esters is distilled in the refinery by heating to approximately 340° C., ester hydrolysis can occur, resulting in the formation lower molecular weight phosphorus compounds that vaporize and distill up the crude tower. Fouling within the towers, exchangers, and furnaces has been linked to the decomposition, hydrolysis and deposition properties of the phosphate esters. Volatile phosphorus is defined as the phosphorus content measured in a distilled fraction. Analysis of foulants removed from distillation towers and furnaces, typically has shown high levels of phosphorus (up to 10%) resulting in:                fouling in jet draw trays within the crude tower resulting in throughput restrictions;        foulant accumulation in pre-flash tower leading to fractionation problems; and        high furnace Tube Metal Temperatures (TMT), in both atmospheric and vacuum furnaces leading to equipment shutdowns.        
Over the last ten years, tower fouling associated with fracturing fluid use has been of increasing concern. There have been periods when it appeared that tower fouling had subsided however recent experience suggests an alarming increase in both phosphorus content in refinery feed and plant fouling. Detailed investigations by the industry determined that residual dialkyl phosphate esters (DAPE) present in marketed mixed sweet blend crude was the primary cause of fouling.
While phosphate esters have been employed as gellants within the industry since the early 70's, fouling of refinery equipment appears to be a cumulative effect and only recently, after years of use, has evidence been uncovered that points to throughput limitations. It is the opinion of the industry that the following factors have combined to impact refinery operability:                increased use of oil-based fracturing fluids;        increased volume of flowback fluids to crude,        changes in gellant/activator chemistry, and        attempts to extend refinery run lengths.        
Further, the use of various organometallic compounds has been found to provide gels that are not stable under reservoir conditions. Problems are particularly prevalent where a significant amount of water is present. Generally, the phosphate-based systems do not satisfactorily perform the desired cross-linking function in the presence of more than about 1200 ppm of water. Further, aluminum cross-linked phosphate ester gels do not perform well where the pH is outside a relatively narrow range.
A number of potential solutions have been proposed, including various alternatives for reducing and/or removing phosphorus from produced crude, as well as employing newly developed low-volatility phosphorus-based additives.
One such solution is to promote use of water-based fracturing which does not utilize phosphorus-based material for the most part. Others have suggested the development of “low-volatile” phosphorus-based gellant systems, utilizing molecules that are less susceptible to high temperature hydrolysis and thus limiting the amount of volatile phosphorus-containing components that transport up the refinery towers. U.S. Pat. No. 7,066,262 to Funkhouser teaches that volatile phosphorus compounds are more related to residual triethyl phosphate ester content of the gelling system rather than thermal instability of the phosphate ester gellants themselves.
Some of the “low volatile” systems suggested are more correctly phosphonate-based systems rather than phosphate ester-based systems. Phosphonate-based components have long been noted as being more stable at high temperature than phosphate ester-based chemistries and, as a result, phosphonate-based molecules have been recommended, for example, in high temperature scale inhibitor work, where historically phosphate ester-based molecules have been shown to be ineffective because of instability at the higher application temperatures.
Historically, U.S. Pat. No. 3,799,267 to Ely et al. and U.S. Pat. No. 4,981,608 to Gunther teach use of fatty acid soaps with metallic compounds for increasing the viscosity of hydrocarbon fluids. Both yield end products that are essentially solid at room temperature and do not meet the preferred requirements of end users for “on the fly” fracturing applications. Many fatty acid organometallic gelling systems currently available on the market, such as from H. L. Blachford Ltd., Mississauga, Ontario, Canada, are only available in a powder form and many require heat to initiate the gelling process. The fatty acid based gellant compounds typically have application in the manufacture of inks and greases and have achieved little market penetration to date into the upstream oil and gas industry. CALFORD® 760, available from H. L. Blachford Ltd., is listed as being an aluminum octanoate which does not require heat to initiate gelling, however the gelling time is well over 3 minutes. Thus, while applicable to hydrocarbon fluids, such compounds are not a practical substitute for phosphorus-based gellant systems.
Further, U.S. Pat. No. 3,799,267 to Ely et al. also teaches the addition of an aromatic acid such as benzoic acid to increase the rheological properties of the gel that is formed by the invention. However, the rate of gellation is limited by the speed at which the solid aluminum soap dissolves in the hydrocarbon fluid and, even though it was postulated that this time could be shortened by the addition of oil-soluble aliphatic acids, no attempt to quantify or claim this enhancement was made. Similarly, U.S. Pat. No. 3,900,070 to Chatterji et al. teaches that di-salts of aluminum 2-ethylhexanoate can be used for gellation of hydrocarbon fluids but the result of using this invention was that gellation times were in excess of 1 hour, mainly due to the lower solubility of the gellant.
U.S. Pat. No. 3,791,972 to Myers et al. teaches that a mixture of aluminum complex soap species can be used for gelling hydrocarbons that are used for the manufacture of lubricating greases. The aluminum complex soaps of this invention were made using an aromatic carboxylic acid and a higher fatty acid which had been reacted sequentially with an aluminum alkoxide. This complex soap mixture was then dissolved in a hydrocarbon to which isobutylene polymer was added. In the case of both Myers et al. and Ely et al., the benzoic acid component of the aluminum soap is critical in terms of rate of dissolution and the resultant gel's rheological properties. In neither case could the invention gel fast enough to be able to satisfy the criteria of “on-the-fly” gellation for practical hydraulic fracturing.
U.S. Pat. No. 6,149,693 to Geib teaches the addition of an alkoxylated amine-based “enhancer” to the invention described in U.S. Pat. No. 5,614,010 to Smith et al. so as to achieve greater gel strengths and quicker gel times. These two patents highlight that phosphate ester-based gelling systems are susceptible to loss of gel strength under certain operating conditions and may have issues with speed of gellation for proper application.
Applicant believes that the systems described thus far encompass the majority of commercially available hydrocarbon gelling systems used by the industry.
Various problems have been encountered with gelled fluids in oilfield applications, including the lack of thermal stability of the fracturing fluids, typically caused by the degradation of the additives or the instability of the gel upon exposure to high temperatures and/or high shear stress conditions. Lack of thermal stability, typically as a result of high temperatures, can result in changes in the rheological properties of the gel, which may ultimately affect the ability of the fluid to suspend the proppant material. If the proppant material is prematurely lost from the fracturing fluid, it can have a detrimental effect on the fracturing treatment. Further, gel instability can result in higher loss of fluid into the formation, diminishing the amount of fracturing that occurs and potentially causing damage to the formation.
U.S. Pat. No. 6,248,699 to Subramanian et al. describes the use of an organometallic salt coupled with an activator, a difunctional or trifunctional carboxylic acid. The activator is used in an attempt to shorten the gelling time. The preferred embodiment is a symmetrical tri-salt of aluminum-2-ethylhexanoate coupled with a dimer-trimer fatty acid which is claimed as being able to from a gel from about 1.5 to about 3 minutes. Subramanian et al. suggest that either aluminum isopropoxide or oxoaluminum acylate may be used however Applicant believes that while aluminum isopropoxide results in a liquid product according to the process described therein, use of oxoaluminum acylate does not, the product being a solid. Applicant believes that embodiments of this gelling system have not achieved any practical use in oil and gas fracturing, possibly due to the following observed short-comings;                the process of manufacture is cumbersome as the product must be manufactured under nitrogen at elevated temperatures;        the product requires approximately 1 minute or more to achieve maximum gel strength; and        the resultant gel is not of sufficient strength to effectively carry large amounts of proppant into deep wells.        
Overall, non-phosphorus based chemistries have achieved little attention in the industry because, to date, they have typically suffered the following disadvantages:                require heat to initiate the gellation process;        are extremely difficult to handle in the field either because they are powders or very viscous liquids, or in some cases are solids;        time taken for the gel to reach its maximum strength is too long for practical applications, being in excess of 30 seconds;        cannot achieve the desired gel strengths to effectively carry sufficient quantities of proppant material into the fractures; and        gels weaken considerably at elevated temperature, thus limiting the applicability for use in shallow formations.        
Recently it has been proposed that oil companies operating in Canada be taxed a levy should produced fluids contain greater than 1.5 ppm phosphorus. Thus, there is great interest in developing fracturing fluids which contain low to no volatile phosphorus and which can be added to fluids and proppant immediately prior to injection into the wellbore.
An ideal solution to the known problems of phosphorus-based technologies is to employ non-phosphorus-based gellant chemistries for use in fracturing systems. Thus, there is great interest in the industry to develop non-phosphorus-based systems which rapidly form gels in oil-based fluids, preferably in less than 30 seconds and more preferably in less than 20 seconds, which are temperature stable and strong enough to carry proppant and which are readily broken using breaking agents to permit hydrocarbons to flow to the wellbore without causing plugging or formation damage.